Apparatus and method for communicating data between a well and the surface using pressure pulses

ABSTRACT

In one aspect, wellbore apparatus is disclosed that includes a conduit that contains a non-circulating liquid therein and is configured to be placed in a well, and a transmitter that is configured to transmit pressure pulses through the liquid in the conduit. In another aspect, a method is disclosed that includes placing a conduit in the wellbore that is closed at one end and contains a liquid medium therein, and transmitting information in the form of pressure pulses through the liquid medium in the conduit.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

This disclosure relates to apparatus and methods for communicating databetween a well and the surface.

2. Background Information

Wells (also referred to as “wellbores” or “boreholes”) are drilled andcompleted to produce hydrocarbons (oil and gas) from one or moreproduction zones penetrated by a wellbore. A typical completed well mayinclude a metallic casing that lines the well. Cement is generallyplaced between the casing and the well to provide a seal between theformation surrounding the well and the casing. Perforations made in theformation through the casing at selected locations across from theproducing formations (also referred to as the “production zones” or“reservoirs”) allow the formation fluid containing the hydrocarbons toflow into the cased well. The formation fluid flows to the surface via aproduction tubing placed inside the casing because the pressure in theproduction zone is generally higher than the pressure caused by theweight of the fluid column in the well. An artificial lift mechanism,such as an electrical submersible pump (“ESP”) or a gas-lift mechanismis often employed when the formation pressure is not adequate to pushthe fluid in the well to the surface.

A variety of devices are used in the well to control the flow of thefluid from the production zones to optimize the oil and gas productionover the life of the well. Remotely-controlled flow control valves andchokes are often used to control the flow of the fluid. Chemicals areinjected at certain locations in the well via one or more tubes that runfrom the surface to the production zones to inhibit the formation ofharmful chemicals, such as corrosion, hydrate, scale, hydrogen sulfide,methane, asphaltene, etc. A number of sensors are typically placed inthe well to provide information about a variety of downhole parameters,including the position of the valves and chokes, pressure, temperature,fluid flow rate, acoustic signals responsive to water front and surfaceor downhole induced signals in the subsurface formations, resistivity,porosity, permeability, water-cut, etc. The measurement data istypically transmitted to the surface via conductors, such as electricalwires, that run from the surface to selected locations in the well.Signals are also sent from the surface to the downhole sensors anddevices via such conductors to control their operations. Such conductorscan degrade over time or become non-functional. It is thereforedesirable to have a data communication system that may be less prone todegradation.

The present disclosure provides improved apparatus, systems and methodsfor communicating data between a well and the surface.

SUMMARY

In one aspect, a method is disclosed that includes: placing a conduitcontaining non-circulating liquid therein in a well; and generatingpressure pulses through the liquid in the tubing to transmit informationbetween a location in the well and the surface. The system may furtherinclude one or more repeaters that detect pressure pulses in the conduitand transmit pressure pulses through the liquid in the conduit thatcorrespond to the detected pressure pulses.

In another aspect, a well data communication system is disclosed thatincludes: a conduit which extends from a downhole location to an upholelocation and a transducer that is configured to send information throughthe liquid medium in the form of pressure pulses. A detector spaced fromthe transducer detects the pulses in the conduit.

In another aspect, an apparatus is disclosed for use in a well thatincludes: a conduit that has a liquid medium therein, which conduit isconfigured to be deployed in the well; and a transducer that isconfigured to generate pressure pulses through the liquid medium in theconduit to transmit data signals.

Examples of the more important features of a well data communicationsystem and methods have been summarized rather broadly in order that thedetailed description thereof that follows may be better understood, andin order that the contributions to the art may be appreciated. Thereare, of course, additional features that will be described hereinafterand which will form the subject of the claims. The summary is providedto provide the reader with broad information and is not intended to beused in any way to limit the scope of the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the apparatus, systems and methods forcommunicating information between a well and the surface, referenceshould be made to the following detailed description, taken inconjunction with the accompanying drawings, in which like elementsgenerally have been given like numerals, wherein:

FIG. 1A shows a schematic diagram of an exemplary well configured toprovide data communication between devices in the well and a surfacecontroller according to one embodiment of the disclosure;

FIG. 1B shows a schematic diagram of certain controllers and devices atthe surface that may be utilized to establish data communication betweenthe well and the surface; and

FIG. 2 shows a functional block diagram of a transducer that may beutilized to generate pressure pulses in a well system to establish datacommunication between a well and the surface, such as shown in FIGS. 1and 2.

DETAILED DESCRIPTION

FIGS. 1A and 1B (collectively referred to herein as “FIG. 1”)collectively show schematic diagrams of an exemplary embodiment of awell system 100 that includes a data communication system between acompleted well 50 and the surface 112 according to one embodiment of thedisclosure. FIG. 1A shows the schematic diagram of the equipment of thewell system 100 that is below the surface 112, while FIG. 1B shows thefunctional block diagram of exemplary equipment of the well system 100that may be deployed at the surface 112 to manage the operations of thesystem 100. The system 100 shows the well 50 formed in a formation 55that produces formation fluids 56 a and 56 b (such as hydrocarbons) fromtwo exemplary production zones 52 a (upper production zone) and 52 b(lower production zone) respectively. The well 50 is shown lined with acasing 57 containing perforations 54 a, adjacent the upper productionzone 52 a and perforations 54 b adjacent the lower production zone 52 b.A packer 64, which may be a retrievable packer, positioned above oruphole of the lower production zone perforations 54 a isolates the lowerproduction zone 52 b from the upper production zone 52 a. A screen 59 badjacent to the perforations 54 b may be installed to prevent or inhibitsolids, such as sand, from entering into the wellbore from the lowerproduction zone 54 b. Similarly, a screen 59 a may be used adjacent theupper production zone perforations 59 a to prevent or inhibit solidsfrom entering into the well 50 from the upper production zone 52 a.

Formation fluid 56 b from the lower production zone 52 b enters theannulus 51 a of the well 50 through the perforations 54 a and into atubing 53 via a flow control valve 67. The flow control valve 67 may bea remotely controlled sliding sleeve valve or any other suitable valveor choke that is configured to regulate the flow of the fluid from theannulus 51 a into the production tubing 53. An adjustable choke 40 inthe tubing 53 may be used to regulate the fluid flow from the lowerproduction zone 52 b to the surface 112. The formation fluid 56 a fromthe upper production zone 52 a enters the annulus 51 b (the annulusportion above the packer 64) via perforations 54 a. The formation fluid56 a enters production tubing or line 45 via inlets 42. An adjustablevalve or choke 44 regulates the fluid flow into the tubing 45. Eachvalve, choke and other such device in the well may be operatedelectrically, hydraulically, mechanically and/or pneumatically by asurface control unit, such as controller 150 and/or by a downholecontrol unit or controller, such as controller 60. The fluid from theupper production zone 52 a and the lower production zone 52 b enter theline 46.

When the formation pressure is not sufficient to push the fluid 56 aand/or fluid 56 b to the surface, an artificial lift mechanism, such asan electrical submersible pump (ESP), gas lift system or other desiredsystems may be utilized to lift the fluids from the well 50 to thesurface 112. In the system 100, an ESP 30 in a manifold 31 is shown asthe artificial lift mechanism, which receives the formation fluids 56 aand 56 b and pumps such fluids via tubing 47 to the surface 112. A cable134 provides power to the ESP 30 from a surface power source 132. Thecable 134 also may include two-way data communication links 134 a and134 b (FIG. 1B), which may include one or more electrical conductors orfiber optic links to provide two-way signals and data communicationbetween the ESP 30, ESP sensors SE and an ESP control unit 130 (FIG.1B).

Still referring to FIGS. 1A and 1B, in one aspect, a variety of sensorsare placed at suitable locations in the well 50 to provide measurementsor information relating to a number of downhole parameters of interest.In one aspect, one or more gauge or sensor carriers, such as a carrier15, may be placed in the production tubing to house any number ofsuitable sensors. The carrier 15 may include one or more temperaturesensors, pressure sensors, flow measurement sensors, resistivitysensors, sensors that may provide information about density, viscosity,water content or water cut, etc., and chemical sensors that provideinformation about scale, corrosion, hydrate, paraffin, hydrogen sulfide,emulsion, asphaltene, etc. Density sensors may provide fluid densitymeasurements for fluid produced from each production zone and that ofthe combined fluid from two or more production zones. The resistivitysensor or another suitable sensor may provide measurements relating tothe water content or the water-cut of the fluid mixture received fromeach production zones and/or the combined fluid. Other sensors may beused to estimate the oil/water ratio and gas/oil ratio for eachproduction zone and for the combined fluid. The temperature, pressureand flow sensors provide measurements for the pressure, temperature andflow rate of the fluid in the line 53. Additional gauge carriers may beused to obtain one or more of the above-noted and other measurementsrelating to the formation fluid received from the upper production zone52 a. Additional downhole sensors may be used at other desired locationsto provide measurements relating to the presence and extent of chemicalsdownhole. Additionally, sensors S₁-S_(m) may be permanently installed inthe wellbore 50 to provide acoustic, seismic or microseismicmeasurements, formation pressure and temperature measurements,resistivity measurements and measurements relating to the properties ofthe casing 51 and formation 55. Such sensors may be installed in thecasing 57 or between the casing 57 and the formation 55. Microseismicand other sensors may be used to detect water fronts, which may aid inmaking adjustments to the flow rates for each zone, chemical injectionrate, ESP frequency, etc. Pressure and temperature changes or expectedchanges may provide early warning of changes in the chemical compositionof the production fluid. Additionally, the screen 59 a and/or screen 59b may be coated with tracers that are released due to the presence ofwater, which tracers may be detected at the surface or downhole todetermine or predict the occurrence of water breakthrough. ESP sensorsSE may include sensors that provide information about temperature,pressure and flow rate of the ESP, differential pressure across the ESP,ESP frequency, power, etc. Sensors also may be provided at the surface,such as a sensor for measuring the water content in the received fluid,total flow rate for the received fluid, fluid pressure at the wellhead,temperature, etc. Other devices may be used to estimate the productionof sand for each zone.

In general, sufficient sensors may be suitably placed in the well 50 toobtain measurements relating to each desired parameter of interest. Suchsensors may include, but are not limited to: sensors for measuringpressures corresponding to each production zone, pressure along thewellbore, pressure inside the tubing carrying the formation fluid,pressure in the annulus; sensors for measuring temperatures at selectedplaces along the wellbore; sensors for measuring fluid flow ratescorresponding to each of the production zones, total flow rate, flowthrough the ESP; sensors for measuring ESP temperature and pressure;chemical sensors for providing signals relating to the presence andextent of chemicals, such as scale, corrosion, hydrates, paraffin,emulsion, hydrogen sulfide and asphaltene; acoustic or seismic sensorsthat measure signals generated at the surface or in offset wells andsignals due to the fluid travel from injection wells or due to afracturing operation; optical sensors for measuring chemicalcompositions and other parameters; sensors for measuring variouscharacteristics of the formations surrounding the well, such asresistivity, porosity, permeability, fluid density, etc. The sensors maybe installed in the tubing in the well or in any device or may bepermanently installed in the well. For example, sensors may be installedin the wellbore casing, in the wellbore wall or between the casing andthe wall. The sensors may be of any suitable type, including electricalsensors, mechanical sensors, piezoelectric sensors, fiber optic sensors,optical sensors, etc. The signals from the downhole sensors may bepartially or fully processed downhole, such as by a controller 60 thatincludes a microprocessor and associated electronic circuitry that is insignal or data communication with the downhole sensors and devices, andthen communicated to the surface controller 150 (FIG. 1B) via asignal/data link, such as link 101. The signals from downhole sensorsmay also be sent directly to the surface controller 150.

A variety of hydraulic, electrical and data communication lines(collectively designated by numeral 20 (FIG. 1A) are run inside the well50 to operate the various devices in the well 50 to obtain measurementsand other data from the various sensors in the well 50 and to providepower and data communication between the surface and downhole equipment.As an example, a tube or tubing 21 may supply or inject a particularchemical from the surface into the fluid 56 b via a mandrel 36.Similarly, a tubing 22 may supply or inject a particular chemical to thefluid 56 a in the production tubing via a mandrel 37. Separate lines maybe used to supply the additives at different locations in the well 50 orto supply different types of additives. Lines 23 and 24 may operate thechokes 40 and 44 and may be used to operate any other device, such asthe valve 67. Lines 25 may provide electrical power to certain devicesdownhole from a suitable surface power source. Two-way datacommunication between downhole sensors, devices located at any one ormore suitable downhole locations and a downhole controller, such as acontroller 60 and/or one or more transducers, such as a transducer 110,may be established by any desired method, including, but not limited to,wires, optical fibers, acoustic telemetry using a fluid line,electromagnetic telemetry, optical fibers, wirelessly, etc.

In one aspect, one or more conduits or tubings, such as tubings 101 and102 are placed or run between a suitable location in the well 50 and thesurface 112 to establish data communication using pressure pulsesthrough a liquid medium in the tubings 101 and/or 102 through. Thetubings may be enclosed at a downhole end and may also be enclosed atthe uphole or surface end. Additionally, the tubings include a suitablenon-circulating liquid, such as water, oil, etc., which is suitable forsending pressure pulses therethrough. The tubings 101, 102 may be madefrom any suitable material, such as an alloy or a composite materialcapable of withstanding the downhole environment for an extended timeperiod. Tubing 102 may be same or similar to the tubing 101. In FIG. 1,tubing 101 is shown in fluid communication with a downhole transducer110, which may include any device that is configured to generatepressure pulses in the liquid medium in the tubing 101. The transducer110 may include a receiver that receives signals or data from one ormore sensors, such a sensors S₁-S_(m) in the well 50 and other devices,such as a sensors that provide signals relating to the position of thesleeve 53, ESP operating parameters, such a flow rate through the ESP,and pump speed, etc. Such data or signals may be provided to thetransducer 110 via any suitable data link, such as electricalconductors, optical fibers or wireless links. The transducer may be anactive device that include a processor, memory and other circuitry thatare configured to receive signals from one or more sensors and devices,process the received signals and transmit the processed signals aspressure signals through the liquid medium in the tubing 101. Theprocessor may use any telemetry scheme, including but not limited to,amplitude, frequency, phase, pulse duration, pulse shape, time betweenthe pulses or any combination thereof. A second transducer 120 spacedfrom the transducer 110 detects or receives the pressure pulses andsends the received signals to a surface controller or control unit, suchas the central controller 150. The second transducer may include anysuitable detector for detecting pressure pulses, such as a pressuresensor. The surface controller 150 decodes the signals received from thereceiver 120 (FIG. 1B) and uses the signals to manage one or moreoperations of the well system 10. The surface controller may send datasignals to the transducer 120, which transmits the received signals viathe liquid media in the tubing 101 in the form of pressure pulses.Alternatively, a separate transducer 122 and tubing 102 may be used tosend pressure pulses from the surface 112 to a downhole controller 60via the liquid medium in the tubing 102. Each of the transducers 110 and120 may be configured to generate the pressure pulses at multiplefrequencies. The pressure pulses may be coded signals and may use anydesired signals modulation technique, such as amplitude, phase,frequency, shape, pulse duration, time between pulses modulation or anycombination thereof. Any suitable device may be used to generatepressure pulses, including but not limited to, a piezoelectric device, apoppet-type pulser, an oscillating-type or shear-wave pulser arotary-type pulser or another suitable pulser.

Wells can be very long and can extend to several thousand meters. Insome such wells, the pressure pulses transmitted by a transducer, such atransducer 110 may attenuate and may not be detectable by the receiver120. In other cases, it may be desirable to transmit pressure pulsesbetween branch wellbores and the surface or a branch wellbore and a mainwellbore via the fluid-filled conduit and the signals may attenuate toan undesirable extent. Also, the transducer 110 over time may not beable to send signals that are strong enough to reach the receiver 120.In any such case, one or more additional transducers 110 or repeaters,such as R₁-R_(n) (generally designated by numeral 114), may be deployedin the well 50 and configured to detect signals from the conduit mediumand retransmit the detected signals to the next repeater and/or thereceiver 120. Similar transducers and repeaters may be deployed in thesecond conduit 102.

Each of the transducers, such as transducer 110, 120 and/or therepeaters R₁-R_(n), may be an autonomous device. FIG. 2 shows afunctional diagram of an autonomous transducer or repeater 200 accordingto one embodiment of the disclosure. The device 200 may include: aprocessor 210, such as a micro-controller, microprocessor or anothersuitable circuit combination; a data storage device or memory device212, such a solid state memory device (Read-only-memory “ROM,” randomaccess memory (“RAM”, flash memory, etc.) that is suitable for downholeapplication; and one or more computer programs or sets of instructions214 that may be stored in the memory 212 and are accessible to theprocessor 210. The processor 210 communicates with the memory 212 andthe programs 214 via links 211 and 213 respectively. A power source 220provides power to the processor 210 as shown by link 221 and to theother components of the device 200 via link 223. In operation, signalsT₁-T_(p) from sensors and other devices may be received by an interface230. The interface 230 may be configured to condition the receivedsignals, such as by amplifying and digitizing the signals. The processor210 processes the signals from the interface 230, such as by sequencingthe signals, putting the signals in appropriate data packets, assigningaddresses of the sensors or the devices from which such signals werereceived by the interface 230, etc. and sends such processed signals vialink 241 to a pulser (transmitter) 240 that sends the signals via themedium in the conduit as pressure pulses. The pressure pulses sent fromthe surface via the conduits 101 and/or 102 are received by a receiveror detector 245, which may condition the received signals and providethem to the processor 210. The processor 210 processes the surface-sentsignals and may control one or more downhole devices 260 or send thesesignals to the downhole controller 60. The processor 210 may store anyinformation in the memory device 212 and/or programs 214 to perform oneor more of the functions described herein. The processor 210 is shown tocommunicate with the receiver 245 via link 243 and with downhole devices260 via link 261. Thus in operation, the downhole transducer 110receives signals from one or more devices or sensors in the well andtransmits signals representative of the received signals as pressurepulses through a liquid-filled conduit placed in the well. A receiverspaced from the downhole transducer detects the pressure pulses andretransmits them to a surface controller for further use. The surfacecontroller may send signals in the form of pressure pulses or by anyother method to a downhole receiver via the same or a separateliquid-filled conduit. One or more repeaters may be provided along theliquid-filled tubing's to retransmit the pressure pulses.

Referring back to FIG. 1B, in one aspect, the exemplary equipment shownin FIG. 1B may be utilized to manage and control the various operationsof the well system 10 in response to the signals received from thedownhole transducer 110. In one aspect, the controller 150 may manageinjection of additives from a chemical injection unit 120 into the well50 to enhance production from one or more zones in response to thesignals received from a chemical sensor that may provide informationabout the presence of certain chemicals, such as scale, hydrate,corrosion, asphaltene, hydrogen sulfide, etc. or in response to awater-cut sensor, resistivity sensor, etc.

In another aspect, the central controller 150 may control the operationof one or more downhole devices directly or via a downhole devicecontrol unit 160 by sending commands via a link 161. The commands may beinstructions to alter the position of a choke or a sliding sleeve, etcand such commands may be in response to signals received from one ormore downhole devices or sensors and/or signals received from a remotecontroller, such as controller 185 that may communicate with thecontroller 150 via a suitable link 189, such as Ethernet, the Internet,etc. The downhole device controller 160 may control the downhole devicesvia links 21-25. In another aspect, the central controller 150 maycontrol the operation of the ESP 30 directly or via an ESP controller130. The ESP controller may control power to the ESP from a power source132 in response to the signals received from the ESP sensors and/orsignals received from the central controller 150.

Thus, in one aspect, a system for communicating information between atleast one location in a well and the surface is disclosed, wherein thesystem includes: a conduit that filled with a non-circulating liquid anda transducer that generates pressure pulses representative of signals tobe transmitted through the conduit. A detector spaced from thetransducer detects the pressure pulses in the conduit and generateselectrical signals representative of the detected pressure pulses.

The transducer may include a pulser that generates the pressure pulsesin the liquid in the conduit. The pulser may be any suitable device thatis configured to generate the pressure pulses downhole, including butnot limited to: a piezoelectric device that generates acoustic signalsto generate the pressure pulses; a poppet-type pulser that includes areciprocating piston or valve that obstructs fluid flow to generatepressure pulses; a shear-wave pulser that generates pressure pulses whena disc oscillates proximate a stationary disc to obstruct fluid flow; arotary pulser that generates pressure pulses when a disc rotatesproximate a stationary to obstruct a fluid flow.

In another aspect, the system may include one or more repeaters upholeof the transducer that detects the pressure pulses generated by thetransducer. The repeater may condition the detected pressure pulses andgenerate the conditioned pulses through the liquid medium in theconduit. The uphole location may be in the well or at the surface. Thesystem may further include a surface transducer that generates pressurepulses in a liquid-filled conduit to a downhole location and a detectordownhole that detects the pressure pulses sent from the surface. Thedownhole detector may provide signals corresponding to the detectedpulses to a downhole controller or processor. In one aspect, thetransducer and/or any of the repeaters may be an autonomous device,which may include: a receiver that receives signals from at least onesensor; a processor that converts the signals received from the at leastone sensor into coded signals; and a pulser that generates pressurepulses in the liquid corresponding to the coded signals. The system, inanother aspect, may further include an interface that receives signalsfrom at least one sensor or device in the well. The sensor or device maybe one or more of: (i) a pressure sensor; (ii) a temperature sensor;(iii) an acoustic sensor; (iv) a flow rate measuring device; (v) awater-cut measurement device; (vi) a resistivity measuring device; (vii)a chemical detection sensor; (viii) a fiber optic sensor; (ix) apiezoelectric sensor; and (x) a density sensor.

The uphole location in the system may be a location in a branchwellbore, a main wellbore, a location at the surface of the earth, alocation at the sea bed, a location on a land rig or a location on anoffshore vessel or platform. The downhole sensors or devices may sendsignals to the transducer or a downhole controller via any suitableconnection, including, but not limited to, electrical conductors,optical fibers and wireless links.

A suitable power source in the well or at the surface may provide powerto the downhole transducers and repeaters, which may include: a battery;(ii) a power generation unit that generates electrical power in thewellbore; and (iii) a power unit at the surface that supplies electricalpower via an electrical conductor disposed in or along the conduit. Theconduit may conduit may be placed: (i) inside a production tubingcarrying fluid to the surface; (ii) between a production tubing and acasing; or (iii) between a casing and formation surrounding thewellbore.

In another aspect, the system may include a plurality of sensorsdistributed in the well, and wherein the system may include a pluralityof transducers, each of which receives signals from an associated sensoror device and transmits coded signals as pressure pulses through theliquid in the conduit that are representative of the received signals.

In another aspect, the system may include an additional liquid-filledconduit that is used to transmit pressure pulses from the surface to adownhole location. Alternatively, the system may include anothertelemetry system for transmitting signals from the surface, such anelectro-magnet telemetry system, an acoustic telemetry system, wire in atubing, etc. Additionally, each transducer and/or repeater may be anautonomous device and may include: an electronics module; and an energysource. The electronic module may further include a processor that actsaccording to programmed instructions for controlling an operation of thetransducer. The energy source may be: (i) a battery; (ii) athermoelectric generator; (iii) a combination of a battery and athermoelectric generator; or (iv) a source at the surface. Thetransducers and repeaters may transmit signals at different frequenciesand at more than one frequency. Additionally, the one or more sensorsassociated with the transducer or repeater may detect at least oneparameter of interest related to: (i) a health of the transducer; or(ii) a downhole condition. The sensors downhole may include any suitablesensor or device, including, but not limited to, sensors for providing ameasurement relating to: (i) pressure; (ii) temperature; (iii)resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity; (vi)density; (vii) presence of a chemical in the wellbore; (viii) paraffin;(ix) scale; (x) hydrate; (xi) hydrogen sulfide; (xii) asphaltene; (xiii)corrosion; (xiv) water content; (xv) presence of gas; (xvi) water cut.

In another aspect, a method is disclosed that includes: placing aliquid-filled conduit in the wellbore; receiving from at least onesensor in the wellbore signals relating to a parameter of interest;transmitting pressure pulses in the liquid in the conduit at a downholelocation that are representative of the signals received from the atleast one sensor; and detecting the pressure pulses at an upholelocation; processing the detected signals to estimate the parameter ofinterest; and recording the estimated parameter of interest in asuitable medium. The method may further include at last one repeaterdevice at a downhole location that detects the pressure pulses,conditions the detected pressure pulses and transmits the conditionedpressure pulses through the liquid in the conduit. The parameter ofinterest may by any suitable parameter, including, but not limited to:(i) pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate;(v) capacitance; (v) viscosity; (vi) density; (vii) presence of achemical in the wellbore; (viii) paraffin; (ix) scale; (x) hydrate; (xi)hydrogen sulfide; (xii) asphaltene; (xiii) corrosion; (xiv) watercontent; and (xv) presence of gas.

In another aspect the method may include: placing a conduit in the wellthat contains a non-circulating liquid medium therein; and transmittinginformation in the form of pressure pulses through the medium, while theapparatus may include: a conduit in a well that contains anon-circulating liquid medium therein and a transmitter configured totransmit pressure pulses through the medium that are representative ofsignals to be transmitted between a downhole location and an upholelocation of a well.

While the foregoing disclosure is directed to certain disclosedembodiments and methods, various modifications will be apparent to thoseskilled in the art. It is intended that all modifications that fallwithin the scopes of the claims relating to this disclosure be deemed aspart of the foregoing disclosure. Also, an abstract is provided in thisapplication with the understanding that it will not be used to interpretor limit the scope or meaning of the claims.

1. A system for communicating information between at least one locationin a well and the surface, the system comprising: a conduit havingnon-circulating liquid therein and extending from a first location inthe wellbore to a second location; a transducer that generates pressurepulses through the liquid in the conduit that are representative of datasignals; and a receiver spaced from the transducer that detects thepressure pulses and generates electrical signals representative of thedetected pressure pulses.
 2. The system of claim 1, wherein thetransducer comprises a pulser that generates pressure pulses in theliquid in the conduit.
 3. The system of claim 2, wherein the pulser isselected from a group consisting of: (i) a piezoelectric device thatgenerates acoustic signals to generate the pressure pulses; (ii) apoppet-type pulser; and (iii) a disc-pulser.
 4. The system of claim 1further comprising at least one repeater that detects the pressurepulses generated by the transducer and retransmits the detected pulsesthrough the liquid medium in the conduit.
 5. The system of claim 1,wherein the transducer generates pressure pulses in the well and whereinthe system further comprises a surface transducer that generatespressure pulses through the liquid in the conduit.
 6. The system claim1, wherein the transducer is an autonomous device that comprises: areceiver that receives signals from at least one sensor; a processorthat converts the signals received from the at least one sensor intocoded signals; and a pulser that generates pressure pulses in the liquidrepresentative of the coded signals.
 7. The system of claim 1, whereinthe transducer receives signals from at least one of: (i) a pressuresensor; (ii) a temperature sensor; (iii) an acoustic sensor; (iv) a flowrate measuring device; (v) a water-cut measurement device; (vi) aresistivity measuring device; (vii) a chemical detection sensor; (viii)a fiber optic sensor; (ix) a piezoelectric sensor; (x) a density sensor;(xi) a downhole controller; and (xii) a surface controller.
 8. Thesystem of claim 1, wherein the detector is uphole of the transducer,which location is selected from a group consisting of: (i) a location atthe surface of the earth; (ii) a location in the wellbore uphole of thefirst transducer: (iii) a location at the sea bed; (iv) a location on aland rig; and (v) a location on an offshore platform.
 9. The system ofclaim 7, wherein the transducer receives the signals via one of: (i) anelectrical wire; (ii) an optical fiber; and (iii) wirelessly.
 10. Thesystem of claim 1 further comprising a power source that provideselectrical power to the transducer, which power source is selected froma group consisting of: (i) a battery; (ii) a power generation unit thatgenerates electrical power in the wellbore; and (iii) a power unit atthe surface that supplies electrical power via an electrical conductordisposed in or along the conduit.
 11. The system of claim 1, wherein theconduit is placed as one of: (i) inside a production tubing carryingfluid to thee surface; (ii) between a production tubing and a casing;and (iii) between a casing and formation surrounding the wellbore. 12.The system of claim 1 further comprising a plurality of sensorsdistributed in the well, and wherein the system further comprises: atleast one secondary transducer in the wellbore that receives signalsfrom an associated sensor in the plurality of sensors and transmitscoded signals as pressure pulses through the liquid in the conduit thatare representative of the received signals.
 13. The system of claim 11,wherein the conduit is sealed at one of: (i) downhole end; and (ii) bothends.
 14. The system of claim 12 wherein the secondary transducercomprises a transmitter that transmits coded signals in a form that isdifferent from the transducer.
 15. The system of claim 1 furthercomprising a second liquid-filled conduit and wherein a secondtransducer sends coded signals through the liquid in the second conduit.16. The system of claim 1, wherein the generated pressure pulses arerepresentative of a parameter of interest that is selected from a groupconsisting of: (i) pressure; (ii) temperature; (iii) resistivity; (iv)fluid flow rate; (v) capacitance; (v) viscosity; (vi) density; (vii)presence of a chemical in the wellbore; (viii) paraffin; (ix) scale; (x)hydrate; (xi) hydrogen sulfide; (xii) asphaltene; (xiii) corrosion;(xiv) water content; and (xv) presence of gas; (xvi) water-cut; (xvii)resistivity; and (xviii) an acoustic measurement.
 17. A method forcommunicating information between a downhole location in a well and anuphole location, the method comprising: placing a conduit in thewellbore, which conduit contains non-circulating liquid therein;transmitting pressure pulses in the liquid in the conduit at firstlocation that are representative of a selected signals; detecting thepressure pulses at a second location and generating signalscorresponding to a selected parameter; processing the to obtain theselected signals; and recording the selected signals in a suitablemedium.
 18. The method of claim 17 further comprising detecting thepressure pulses at a third location that is between the first and secondlocations and retransmitting the detected pressure pulses at the thirdlocation.
 19. The method of claim 17, wherein the selected parameter isselected from a group consisting of: (i) pressure; (ii) temperature;(iii) resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity;(vi) density; (vii) presence of a chemical in the wellbore; (viii)paraffin; (ix) scale; (x) hydrate; (xi) hydrogen sulfide; (xii)asphaltene; (xiii) corrosion; (xiv) water content; and (xv) presence ofgas.
 20. The method of claim 17, wherein the conduit is placed in thewell in a manner that is one of: (i) inside a casing in the wellbore;(ii) between a casing in the wellbore and the formation surrounding thewellbore; (iii) inside a production tubing that carries the wellborefluid.
 21. A method for communicating in a well, comprising: placing aconduit in the well that contains a non-circulating liquid mediumtherein; and transmitting information in the form of pressure pulsesthrough the liquid medium.
 22. An apparatus, comprising: a conduitconfigured to be deployed in a well, which conduit is closed at one endand contains therein liquid; and a transmitter configured to transmitinformation in the form of pressure pulses through the liquid at aselected location in the conduit.